Responding to stakeholder demands to resolve a yearlong dispute, PJM’s Stu Bresler has sent a letter outlining his requirements for accepting the Independent Market Monitor’s opportunity cost calculator.
The public pronouncement of PJM’s terms was unexpected but welcomed. “I’m surprised that PJM has apparently decided to negotiate this publicly,” Monitor Joe Bowring said. “We will respond.” Bowring declined to address whether PJM’s terms were acceptable and detailed enough.
For more than a year, PJM and its Monitor have been unable to agree on a single calculator for opportunity costs included in generation offers. PJM argues that FERC Order 719, issued in October 2010, allows the Monitor to provide input on cost determinations but that “PJM retains the ultimate decision-making authority.” From then until “the latter part of 2016,” both calculators produced consistent results, Bresler said in his letter, but have since diverged substantially.
PJM says it can’t endorse the Monitor’s calculator until staff understand how and why it produces different results. For that reason, PJM announced in August it would only accept opportunity cost calculations using its calculator.
The Monitor argues that it has continued to enhance its calculator while PJM hasn’t changed its methodology since 2010.
PJM staff have asked to understand the calculator’s inner workings, but Bowring has been reluctant to fully throw back the curtain, arguing that PJM staff haven’t specifically detailed their requests and that the underlying computer code is proprietary intellectual property.
Generators say the dispute has left them in a bind, fearing a referral to FERC enforcement for using an unapproved number.
At the Aug. 23 Markets and Reliability Committee meeting, generators attempted to force a resolution by threatening Tariff revisions that would require PJM to accept the Monitor’s calculator. (See Stakeholder Proposal Aimed at Ending PJM-IMM Dispute.)
Bresler’s letter details three requests to the Monitor:
the design requirement specification documents for the Monitor’s calculator, including descriptions of steps taken to calculate adders and accompanying mathematical formulas.
alternatively, the calculator’s output from pre-defined sample inputs and parameters so PJM can compare the results with its calculator’s output using the same inputs.
a commitment to notify PJM of any changes to the calculator and to rerun the comparative analyses afterward.
Bresler, PJM’s senior vice president of operations and markets, shot down an earlier suggestion from Bowring that they allow a third-party auditor to compare the calculators, saying it was less efficient and more expensive than his solutions. He gave Bowring a Sept. 10 deadline to respond to the proposal.
The Members Committee is set to vote on the proposed Tariff revisions on Sept. 27, barring an agreement before then.
Order 890’s transparency provisions do not apply to “asset management” projects that provide only “incidental” increases in transmission capacity, FERC ruled in two orders Friday.
The commission rejected complaints by California regulators and others who contend Pacific Gas and Electric and Southern California Edison are violating Order 890’s transparency provisions because much of their transmission planning is done without stakeholder input or review.
The California Public Utilities Commission, Northern California Power Agency, the city and county of San Francisco, the State Water Contractors and the Transmission Agency of Northern California filed the complaint against PG&E in February 2017.
The agencies complained that PG&E offered no stakeholder or external review on almost 80% of its transmission capital projects, including substation upgrades, replacement of deteriorating transmission equipment, system reliability and automation, and technology infrastructure.
| PG&E
But the commission said such activities were generally not subject to Order 890 because they provide no more than incidental increases in transmission capacity — such as replacing a 1940s-vintage transformer with modern equipment “which could be of a higher capacity if the PTO [participating transmission owner] has standardized transformer sizes across its system to allow for sparing should the transformer fail” (EL17-45).
“While Order No. 890 does not explicitly define the scope of ‘transmission planning,’ the commission adopted the transmission planning requirements in Order No. 890 to remedy opportunities for undue discrimination in expansion of the transmission grid,” FERC said. “Based on the information in the record, we find that the specific asset management projects and activities at issue here [are designed to] maintain [PG&E’s] existing electric transmission system and meet regulatory compliance requirements.”
The commission acknowledged asset management could result in significant transmission capacity increases, “for example, where a PTO determines that it can address a CAISO-identified transmission need by expanding the scope of an asset management project or activity to result in a capacity increase.”
“Accordingly, the incremental portion of the asset management project or activity would be subject to the transmission planning requirements of Order No. 890 and would have to be submitted for consideration in CAISO’s [transmission planning process] through the request window. If CAISO did not approve the incremental work, then the PTO should not expand the scope of the original asset management project or activity without that work being subject to consideration through an Order No. 890-compliant transmission planning process.”
The commission also said it “strongly encourage[s] PG&E to continue its efforts to work with complainants and other stakeholders to develop a process to share and review information with interested parties regarding asset management projects and activities that are not considered through the” CAISO transmission planning process.
SoCal Edison Review Process OK’d
FERC used the same reasoning in rejecting the PUC’s request for a show-cause order finding that Order 890 governs transmission owners’ planning for self-approved projects.
Instead, the commission approved SCE’s tariff change creating a process for sharing information with stakeholders about its asset management projects not subject to Order 890 (ER18-370, AD18-12).
The commission said the transmission maintenance and compliance review process “offers transparency and the opportunity for stakeholders to have input into the development of SoCal Edison’s transmission rates.” It ordered SCE to make a compliance filing within 30 days adding provisions the company proposed in response to protesters’ concerns.
FERC has granted PJM’s request to delay its annual Base Residual Auction, from May to Aug. 14-28, 2019, after recently extending filing deadlines for its paper hearing on the RTO’s capacity construct (ER18-2222).
| AdobeStock
The initial and reply testimony deadlines were extended to Oct. 2, 2018, and Nov. 6, 2018, respectively, at the request of the Organization of PJM States Inc. (OPSI). FERC ordered the hearing after rejecting both proposals PJM offered in its “jump ball” filing and ruling that the RTO’s existing capacity construct isn’t just and reasonable. FERC instead suggested a fixed resource requirement (FRR) hybrid.
PJM asked for the delay because the extended comment deadlines indicated that FERC would be unlikely to issue a ruling on the hearing by Jan. 4, 2019, the date that PJM previously said would accommodate holding the BRA as planned in May while still including whatever revisions FERC orders.
Several PJM stakeholders have proposed revisions to the capacity auction. PJM recently unveiled to stakeholders and nondecisional FERC staff its proposal, which it dubbed the Resource-specific Carve Out (ReCO). It would start with a subsidized generation resource exiting the capacity market with a corresponding amount of load rather than the FRR’s inverse of a designated amount of load exiting the capacity market with a corresponding resource. (See PJM Unveils Capacity Proposal.)
On Aug. 29, the commission issued a procedural order granting itself more time to consider motions requesting rehearing of its order recommending the capacity market changes (EL16-49, et al.).
FERC on Friday accepted revisions to PJM’s long-term financial transmission rights auctions to correct current processes that might overstate available system capacity and harm auction revenue rights holders (ER18-1968).
The current process allows long-term FTR market participants to obtain the rights to congestion on transmission paths before the owners of the underlying ARRs.
Following each annual FTR auction, PJM conducts a long-term FTR auction for the three planning years immediately following the planning year during which the long-term FTR auction is conducted. Offered for sale is the residual system capability after the annual ARR allocations and the annual FTR auction. In determining the residual capability, PJM assumes that all allocated ARRs are self-scheduled into FTRs, which are modeled as fixed injections and withdrawals in the long-term FTR auction.
Cleared auction volume (MW) as a percent of total FTR cleared volume by calendar month | Monitoring Analytics
Under the new rules, PJM will revise how it compiles the paths available in the auction by conducting an additional, offline annual allocation of ARRs prior to the opening of each round of the long-term FTR auction. The procedure will use the same topology as the annual ARR allocation except that all transmission outages will be returned to service and PJM will perform its simultaneous feasibility test to determine the set of ARRs to be preserved for the long-term FTR auction. (See “Stakeholders Approve Manual, Operational Changes,” PJM MRC/MC Briefs: June 21, 2018.)
FERC also granted PJM’s request to eliminate the three-year long-term FTR product. The auction currently offers FTRs separately for each of the subsequent three planning years, as well as for all three years combined. Historically, bidding for the three-year product is low and eliminating it will increase the efficiency of PJM’s FTR software, the RTO said.
The commission also granted PJM’s Sept. 3 effective date in order to implement the changes in the next round of its long-term FTR auction commencing Sept. 4.
RTO Insider filed a complaint Friday asking FERC to overturn the New England Power Pool’s ban on press coverage of its meetings or terminate the group’s role and direct ISO-NE to adopt an open stakeholder process similar to those used by other RTOs.
The Section 206 complaint (EL18-196) comes two weeks after NEPOOL submitted a proposal to FERC seeking to codify an unwritten policy of banning news reporters and the public from attending the group’s stakeholder meetings . (See NEPOOL Files Press Ban with FERC.) New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.
NEPOOL’s proposed amendments to the NEPOOL Agreement would add a definition of “press” and bar anyone working as a journalist from becoming a NEPOOL member or alternate for a participant. The group drafted the revisions after RTO Insider reporter Michael Kuser, who lives in Vermont, applied for membership in NEPOOL’s Participants Committee as an end-user customer in March.
Chilling Discussion?
In its filing, NEPOOL contended that allowing press to become a participant “would adversely impact the power pool’s ability to continue to foster candid discussions and negotiations in its stakeholder meetings.” Absent those discussions among its members, ISO-NE and state officials, NEPOOL “would be limited in its ability to narrow or resolve complex issues within the NEPOOL stakeholder process,” the group said.
It cited concerns that press attendance at meetings “could encourage public posturing, pre-scripted statements and reduced willingness or ability by members to freely explore ideas or solutions.”
FERC Commissioner Neil Chatterjee spoke at NEPOOL’s December Participants Committee meeting at the Colonnade Hotel in Boston. | NEPOOL
NEPOOL’s case for maintaining privacy pivots on the argument that it does not function in the same manner as other RTOs. Its filing notes that “unlike other regional transmission organizations in which stakeholders are assembled by and at the direction of the particular RTO, NEPOOL is and always has been an independent, separately organized stakeholder body.”
To support its claims, the power pool’s filing included the testimony of Robert Stein, principal consultant at Signal Hill consulting group, who said he has participated in the NEPOOL stakeholder process since beginning his career in the power industry in 1971.
Stein testified that the power pool’s meetings have always been “nonpublic,” and expressed concern that the press’ presence would change the “tenor and tone” of NEPOOL meetings “in a very unhelpful way.”
“Over the years I have both observed and participated in discussions at meetings where positions were taken and changed in our non-public setting,” he said. “This would be much less likely if members are concerned that those positions, as they may evolve during the NEPOOL process, could appear in press reports and need to be defended publicly. There are many examples, such as in diplomacy and labor negotiations, where the ability to negotiate outside the public spotlight is important if not essential.”
‘No Apparent Basis’
RTO Insider responded that Stein “has no apparent basis for this speculation” given his testimony that NEPOOL meetings have always been nonpublic and that he has worked his entire career in New England.
RTO Insider estimated it has covered 900 stakeholder meetings in the other six RTOs/ISOs since 2013 and said its reporters can recall fewer than 10 instances of a stakeholder representative reading from a prepared speech.
RTO Insider’s Aug. 31 complaint contended that nonpublic meetings violate the public interest and the missions stated in ISO-NE’s and NEPOOL’s governing documents.
It also contested NEPOOL’s assertion that it is a private organization, saying that FERC precedent “hardwires the NEPOOL stakeholder process into the regulatory process by requiring its use.” It noted that ISO-NE’s Participants Agreement with NEPOOL requires the RTO “to present proposals for changes to market rules, operating procedures, manuals, reliability standards, general tariff provisions, or non-[transmission owner] [open access transmission tariff] provisions for governance participant consideration and NEPOOL participant vote.”
NEPOOL conducted 253 votes on 56 meeting days in 2017. All the meetings were closed to the public and press. | NEPOOL
RTO Insider pointed to another special privilege enjoyed by NEPOOL: its so-called “jump ball” filing rights at FERC. In cases when ISO-NE submits a market rules proposal that differs from one approved by the Participants Committee on a 60% vote, that provision entitles NEPOOL to file a competing proposal that the commission can adopt in full.
“This is an extraordinary right because it negates the right an RTO/ISO would otherwise have for its [Federal Power Act] Section 205 filing to be accepted if just and reasonable (or not unjust and unreasonable), rather than having to demonstrate that its filing is superior to alternatives,” RTO Insider contended.
The publisher also contended that, given NEPOOL’s role in transmission planning, failure to provide openness and transparency violates FERC Order 890. Banning the press and public from meetings also discriminates against smaller entities and potential new entrants to the New England market, the complaint said.
The publisher noted that ISO-NE, through NEPOOL, is the only RTO/ISO in the country that bars the press and public from its stakeholder process. “NEPOOL is well aware of this uniqueness, but nowhere in its 15-page transmittal letter in support of formalizing its press ban does it attempt to explain why ISO-NE/NEPOOL are fundamentally different from all the other RTO/ISOs,” the complaint said. “Nowhere does NEPOOL explain why secrecy is critical for it and it alone.”
RTO Insider said that if the power pool can justify its press ban as a “private” entity desiring secrecy, “its special powers and privileges should be transferred to an open stakeholder process within ISO-NE, and the ISO-NE resources devoted to NEPOOL (currently $2.6 million annually) should be devoted to an open stakeholder process within ISO-NE.”
NEPOOL Docket
RTO Insider also will file the complaint as a protest in the docket opened by NEPOOL (ER18-2208).
No one else has thus far filed substantive comments, although Consolidated Edison, Avangrid, Public Citizen and New Hampshire Consumer Advocate D. Maurice Kreis have filed motions to intervene. FERC extended the deadline for comments in that docket by 10 days to Sept. 14.
“Somehow the nation’s other six RTOs manage to make difficult policy choices without a secret governance body for stakeholders,” Kreis said in a June 25 blog post on InDepthNH.org.
Kreis told RTO Insider that he found the argument that press attendance will have a chilling effect on NEPOOL stakeholder discussions “to be cosmically unpersuasive.”
“I don’t get to go to a lot of NEPOOL meetings. Having third-party summaries of meetings [from the press] is going to help me do my job,” he said.
FERC last week approved a reduced return on equity for Pioneer Transmission’s portion of a recently completed 765-kV line in Indiana.
The commission’s Aug. 30 order reduces Pioneer’s ROE to 10.82% from the 12.54% approved in 2009, which included a 150-basis-point (bp) adder as a new interregional project (ER18-1159).
Pioneer, a joint venture of American Electric Power and Duke Energy, will use the ROE in its formula rates to recover costs for it and Northern Indiana Public Service Co.’s 65-mile, 765-kV Greentown-to-Reynolds line.
Pioneer in March proposed to adopt MISO’s 10.32% base ROE for transmission owners, with a 50-bp adder for RTO participation and the 150-bp adder for new transmission.
FERC allowed the base ROE and adder for RTO participation but denied the 150-bp adder because the current project does not include PJM.
Regional Processes
The Pioneer Project was intended as a single, $1 billion, 240-mile project across MISO and PJM to address “a critical shortage of high voltage transmission” in Indiana and help transport new wind generation from the state’s southwest to its central and northern regions.
At the time the project was proposed a decade ago, the MISO-PJM interregional planning process did not have “a tariff mechanism in place for evaluating and approving an interregional project such as the Pioneer Project that provided benefits to both RTOs,” according to Pioneer.
The company said it broke the project into smaller segments to be reviewed under PJM’s and MISO’s separate regional processes after encountering difficulties getting the RTOs to approve the line as an interregional project.
Pioneer and NIPSCO took up a $347 million Greentown-Reynolds line, which was approved in MISO’s 2011 multi-value project portfolio. This June, the MISO Board of Directors voted to add Pioneer as a MISO TO, and Pioneer has handed over operational control of the completed line.
FERC said the 150-bp adder would not go into effect “unless and until the project is approved by the regional transmission planning processes of [PJM and MISO] and there is a commission-approved cost allocation methodology in place.”
FERC said because the line had been broken into regional segments, it could not meet the condition that the Pioneer Project be included in both the PJM and MISO transmission plans. Pioneer had argued that the condition was no longer applicable or should be waived because the project “continues to be a large-scale transmission project and the first 765-kV transmission facilities in MISO’s service area.”
In its Aug. 30 order, FERC said Pioneer was free to apply for the new transmission incentive again once it could satisfy the requirement.
“Our denial of the 150-basis-point ROE adder is without prejudice. If Pioneer satisfies the commission’s previously stated conditions, then Pioneer may make a Section 205 filing to seek to prospectively implement the full 150-basis-point ROE incentive that the commission previously granted,” FERC said, adding that it “continues to value transmission rate incentives as a tool to encourage investment in new transmission.”
“In that vein, we encourage Pioneer to continue its efforts to complete the Pioneer Project,” the commission said.
NYISO’s Management Committee agreed Wednesday to relax its minimum 20-MW constraint reliability margin value in its initiative to price transmission constraints on 115-kV facilities.
The ISO’s Tariff currently requires at least 20 MW be set for any non-zero constraint reliability margin value used in the day-ahead and real-time markets
David Edelson, NYISO manager of operations performance and analysis, noted as an example that a 20-MW CRM equals 13% of the rating for 115-kV lines with post-contingency limits of 150 MW, limiting them to 130 MW in dispatch.
115-kV transmission line | Exponential Engineering
By contrast, for a 345-kV circuit with a 1,550-MW post-contingency rating, a 20-MW CRM represents only about 1% of the line rating.
Edelson said the ISO wants to limit CRMs to no more than 10% of a facility’s rating to allow for the continued pricing of transmission constraints on lower-voltage lines.
NYISO wants to change the Tariff to permit CRMs of less than 20 MW until it can implement enhancements under its constraint-specific transmission shortage pricing project. The ISO said the timing of that project is subject to stakeholders’ prioritization and scheduling.
The ISO would publish on its website a list of transmission facilities and interfaces assigned a CRM other than 20 MW.
The rule change will be presented to the Board of Directors for approval in September. The committee approved the proposal unanimously by a show of hands.
The Public Utility Commission of Texas last week approved a settlement agreement reducing AEP Texas’ annual revenue requirement (ARR) by $27 million, largely to reflect last year’s federal income tax legislation (Docket No. 48222).
AEP Texas agreed to reduce the revenue requirement in its distribution-cost recovery factors (DCRFs) to $55.6 million, with AEP Central’s ARR cut by $21.2 million and AEP North’s by $5.8 million.
Commission staff, the Alliance for Retail Markets (ARM) and several cities served by AEP signed on to the agreement. Texas Industrial Energy Consumers and the Office of Public Utility Counsel did not sign the agreement, but they are not opposed to it.
The changes, effective Sept. 1, reflect the reduction in the federal income tax rate from 35% to 21%.
The commissioners approved similar settlement agreements filed by CenterPoint Energy (Docket 48226) and Oncor (Docket 48231).
CenterPoint, which requested an ARR of $82.6 million effective Sept. 1, agreed to $42.4 million, rising to $63.7 million in September 2019, reflecting other tax changes.
Oncor agreed to a DCRF based on an ARR of $15.2 million, also effective Sept. 1. The utility had requested an ARR of $19 million.
Left to right: Commissioners Shelly Botkin, DeAnn Walker and Arthur D’Andrea share their thoughts | Admin Monitor
PUC Chair DeAnn Walker expressed reservations with the AEP settlement during the commission’s Aug. 30 open meeting, noting that state statutes require DCRF adjustments “be applied by the electric utility on a systemwide basis.” She pointed out that the commission’s 2016 approval of the merger of AEP Texas Central and AEP Texas North into AEP Texas required the company to maintain separate divisions with separate rates, riders and tariffs (Docket 46050).
“Systemwide rates would require a rate that is in effect for the entire AEP Texas system,” Walker said, pointing to the settlement agreement’s separate DCRF rates for AEP’s Central and Northern divisions.
AEP legal counsel Melissa Gage said the company’s interpretation of the law “wasn’t intended to mean systemwide in terms of AEP Texas as a whole, but on a division basis.”
Steve Davis, representing ARM, agreed with AEP’s interpretation and said the case posed “an odd situation.”
“It’s kind of hard to make it all fit correctly,” he said. “You have the statutory language, then you have the commission’s order in the merger case, which talks about separate rates” until some point in the future, he said. “Maybe there’s a path in future DCRF cases to follow to get to where you want to go.”
The commissioners saved further discussion on the proceeding for their closed session, which apparently eased Walker’s concerns. “I’m fine with moving forward,” she said afterward.
Commissioner Arthur D’Andrea pointed out the DCRF order is temporary, as AEP Texas is scheduled to file a full rate case in May. AEP Texas’ 8.96% rate of return last year was below that authorized by the commission during its last rate proceeding, according to the company’s 2017 earnings monitoring report.
Hearings Set for AEP Texas Legal Cases
AEP Texas also figured in two orders on the commission’s consent agenda.
The PUC first approved a procedural schedule for AEP’s bid to recover about $415 million in system restoration costs for 2017’s Hurricane Harvey. The schedule includes a Nov. 13-14 hearing before an administrative law judge (Docket 48577). AEP has proposed using a portion of its excess deferred taxes created by last year’s federal tax legislation to reduce the system restoration costs it will recover from consumers.
The commission also approved a procedural schedule in the company’s dispute with Rio Grande Electric Cooperative over which utility will serve certain customers in a Uvalde subdivision (Docket 47186).
An ALJ ruled on Rio Grande’s request for a cease-and-desist order in June, finding that AEP lacked the authority to serve some, but not all, of the customers in the disputed area. The case is of interest to retailers because Rio Grande’s service territory is not open to retail competition while competition was introduced in AEP’s footprint in 2002.
The procedural schedule for the second phase of the case includes a hearing to be held Oct. 31.
Commissioners Grant CCN to Tx Project — and Pole
The commission granted AEP Texas and Brazos Electric Power Cooperative a certificate of convenience and necessity for a jointly owned transmission line after the parties agreed to name a pole marking the midway point between them (Docket 47691).
Under the CCN, the two companies will each construct and operate half of the 138-kV transmission line southeast of the Texas Panhandle. The 20-mile line will connect Brazos’ Gyp switching station to AEP’s expanded Benjamin substation.
AEP Texas’ Jerry Huerta (left), Brazos Electric’s Bill Spears | Admin Monitor
The utilities have yet to determine which one will own the pole, which represents a new interconnection point between the two. After jokingly offering to paint the pole two different colors, the utilities’ legal counsel took advantage of free time during the commissioners’ executive session to agree on a name for the pole: Gyp-to-Benjamin Terminus.
“We thought long and hard about the name but came up with what’s written there,” AEP’s Jerry Huerta said, as the commissioners stared quizzically at their documents.
The project will cost an estimated $20 million. No word on how much the terminus pole will cost.
Entergy Texas Gets OK for 230-kV Line
The commissioners also granted a CCN to Entergy Texas for a proposed 230-kV line north of Houston (Docket 47462). The line is one element of a MISO western region project identified in its 2015 Transmission Expansion Plan that will provide economic benefits to MISO South. It will be between 33 and 45 miles long and cost up to $140 million, depending on the final route. Entergy plans to energize the line in June 2020.
October Workshop to Review ERCOT’s Summer Performance
The commission will hold a workshop in late October to review ERCOT’s market performance this summer (Project 48551). The workshop is intended to be an open meeting, with all three commissioners attending.
The commission in March directed ERCOT to exclude reliability unit commitments from online reserve capacity used in the calculation of the operating reserve demand curve price adder. It said at the time that further market design changes would be examined after an analysis of the market’s summer performance.
Luminant Accepts $1.1M Penalty for 2015 Violations
The PUC on Aug. 17 approved a settlement agreement with Luminant, in which the generation company agreed to pay a $1.1 million administrative penalty for violations in 2015. Luminant was fined for telemetering a down ramp rate of zero for 15 quick-start units when they were operating near full capacity for four days that summer, preventing ERCOT from dispatching the units down.
In his “Counterflow” column in the July 31 issue of RTO Insider, Steve Huntoon makes the unusual argument that because offshore wind costs more than onshore wind (i.e., requires more subsidies) offshore wind is a waste of money by a factor of 11:1 according to the Lazard study. Thus, we should build only onshore wind and forget about offshore wind.
Burdock | Business Network for Offshore Wind
However, there is plenty of evidence that offshore wind costs are rapidly coming down, and that some of offshore wind’s key benefits, especially its proximity to the population centers along the U.S. East Coast and job creation, make it a good value for ratepayers.
Mike O’Boyle, electricity policy manager for Energy Innovation, recently cited a Lawrence Berkeley National Laboratory (LBNL) study that showed “the high capacity factors of offshore wind, the coincidence of wind with customer demand, and the potential locations adjacent to congested coastal load centers like New York and Boston already make offshore wind an economic option.”
The LBNL study also found that the “market value” of offshore wind — considering energy, capacity and renewable energy certificates (RECs) — varies significantly along the U.S. East Coast, and “generally exceeds that of land-based wind in the region.”
The dramatic unveiling on Aug. 1 of the Massachusetts Department of Energy Resources’ 6.5-cents/kWh (in 2017 dollars) price for the Vineyard Wind project really brings this point home. In fact, the state estimates that Massachusetts electricity customers will see $1.4 billion in direct and indirect benefits over the 20-year life of the Vineyard Wind contract.
But there’s a larger problem with Mr. Huntoon’s claims that the Lazard study tells us that offshore wind is too expensive, and that the PJM territory has plenty of room for onshore wind. They center around transmission and distribution, which were “other factors” that were not included in the scope of the Lazard analysis. The simple fact is that most people don’t want to live near major electric transmission lines, which is why several transmission projects in New York and New England have been voted down by local and regional boards, and why New Jersey has virtually no onshore wind farms — and no plans to build any.
Several PJM states have a lot of land to build onshore wind; however, in coastal states like Maryland and New Jersey, the onshore wind resource is very small and as mentioned above difficult to site. According to the American Wind Energy Association, Maryland ranks 31st (191 MW) and New Jersey ranks 39th (9 MW) in installed onshore wind capacity. AWEA also estimates between 101 to 500 direct and indirect jobs are supported by onshore wind in both states.
| BithEnergy
Mr. Huntoon says the offshore wind jobs are a scam. It is hard to scam job creation when the Maryland Public Service Commission requires as a condition of the offshore renewable energy credit (OREC) order that US Wind and Skipjack invest $1.8 billion of in-state spending to spur the creation of almost 9,700 new direct and indirect jobs. Not only that, the two offshore wind developers must contribute $74 million in state tax revenues over 20 years.[1] Remember, those numbers must be met before one penny is paid to the developers. (OREC payments are not provided until the project is built and the offshore wind turbines are generating power.)
Mr. Huntoon is correct when he says, “It is critical that we make the most of our collective money” — a tenet the PSC understood when it decided to finance Maryland’s two offshore wind projects as a way to meet the state’s renewable portfolio standard and generate jobs. Maryland’s primary objective for its RPS is to foster the development of renewable energy resources within Maryland, but this goal has largely not been borne out.[2] Maryland’s data suggest that a significant portion of its REC costs paid for out-of-state onshore wind and solar. In fact, every year electricity suppliers in Maryland purchased greater numbers of out-of-state RECs to comply with the RPS. The Maryland Energy Administration (MEA) estimates that in 2015, Maryland ratepayers paid more than $76 million for RECs that were generated out-of-state. MEA estimates that as much as $186 million, if not more, has been spent to acquire non-Maryland RECs.[3] There is no in-state spending requirement, nor Maryland tax revenue generated, with these out-of-state projects — just millions of state ratepayer dollars going to other states. Isn’t that the real scam?
So, if we consider that offshore wind is a proven power producer in Northern Europe; offshore wind turbines are getting much bigger (see General Electric’s 12-MW turbine) and more productive than onshore turbines; offshore wind is stronger and more consistent than onshore wind; and offshore costs are coming down faster than anticipated, you can see why states like Massachusetts, New York, New Jersey and Maryland are counting so heavily on offshore wind. Yes, it’s going to take some upfront investment to establish the industry in the U.S., but those costs will be more than offset by the superior value provided by offshore wind over the next 20 to 30 years and beyond.
Liz Burdock is executive director of the Business Network for Offshore Wind.
Generating Clean Horizons was an effort to stimulate this goal because the RPS on its own did not result in clean electricity generation within the state. ↑
A controversial bill to help California utilities pay for wildfires sparked by power lines cleared the State Legislature on Friday night and was sent to Gov. Jerry Brown.
SB 901 would allow the state’s investor-owned utilities to issue cost-recovery bonds, to be repaid by charges on customers electric bills, with the approval of the Public Utilities Commission.
Proponents argued it was a way to keep Pacific Gas and Electric and other utilities solvent at a time when wildfires are larger, more intense and far more costly than in prior years. Climate change is often blamed for the more deadly and destructive fires.
“SB 901 is a comprehensive approach that attacks the problems on multiple levels,” said Sen. Bill Dodd (D-Napa), the measure’s co-author, during Friday’s floor debate.
Critics called it a giveaway to utilities that, through their own negligence, allowed power lines to ignite trees and brush that are tinder dry from years of drought.
“This bill rewards their bad behavior,” said Sen. Jerry Hill, a Democrat who represents the Silicon Valley.
The bill was the subject of intense wrangling this summer.
A July 24 proposal by Brown would have done away with California’s broad use of inverse condemnation, a legal doctrine that holds utilities strictly liable for fire damage. Many argued that overturning the longstanding doctrine would leave fire victims without quick compensation. That part of the governor’s plan was not included in the bill.
Instead, a conference committee of Senate and Assembly members met seven times in recent weeks to hear testimony and gather information to redraft the measure. The committee approved a revamped proposal in a late-night scramble Tuesday, and its report passed the Senate and Assembly by ample margins Friday as the legislature neared its midnight deadline for passing bills.
The rewritten measure would maintain the state’s strict liability standard and require the PUC to determine the reasonableness of a utility’s fire safety practices in deciding whether costs can be passed on to ratepayers.
SB 901 would also require utilities to adopt wildfire mitigation plans and would create a commission to examine catastrophic wildfires associated with utility infrastructure. It would levy fines on utilities that fail to adhere to their fire-prevention plans.
As a result, utilities that once supported the measure turned against it, while insurers, plaintiffs’ attorneys and local governments switched their opposition to support.
| U.S. Dept. of Agriculture
The bill’s 100-plus pages also ease rules for tree cutting and address the disposal of the massive amounts of dead wood and brush that fuel wildfires. It would spend $1 billion over five years on fire prevention.
The bill also includes a “stress test” that instructs the PUC to “consider [an] electrical corporation’s financial status and determine the maximum amount the corporation can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service.”
The provision applies only to last year’s wildfires, including the highly destructive blazes of October 2017 that killed dozens of residents and leveled thousands of homes in Napa and Sonoma counties. A large part of the city of Santa Rosa burned in the wind-whipped flames.
State investigators have determined that PG&E’s equipment was responsible for a number of the most destructive fires from that time and the company will face $15 billion or more in liability, according to some estimates.
The PUC would apply the stress test “to extract the maximum amount possible” from PG&E’s investors, Dodd said. Letting PG&E slip into bankruptcy would result in customers paying higher rates and would compromise the state’s efforts to reduce greenhouse gasses and to tap into greater amounts of renewable energy, he said.
Wildfires have burned 1.2 million acres in California already in 2018. The causes of most of the fires have yet to be determined. The blazes included the Mendocino Complex of fires that have burned more than 400,000 acres in the mountains north of San Francisco.
Brown has not yet indicated whether he will sign or veto the measure. He has until Sept. 30 to decide.
